The present invention relates generally to hydrogen production and more specifically to a method for producing hydrogen from catalytic steam reformers and gasifiers.
Upgrading of heavy oil into more valuable products usually requires large quantities of hydrogen. Traditionally, this hydrogen is generated by catalytically reacting natural gas and steam in a so-called steam-methane reformer (SMR). More recently, refiners engaged in upgrading projects are considering gasification of petroleum coke or heavy oil as a more cost effective means for generating the large quantities of hydrogen required. This is being driven by the increased cost of natural gas compared to the low cost of a gasifier feedstock.
In steam-methane reforming, natural gas or other suitable feedstock is mixed with an appropriate amount of process steam and heated as it flows through catalyst filled tubes contained within the steam-methane reformer furnace. In the reformer tubes, a portion of the process steam and most of the natural gas feed is converted to synthesis gas (syngas), which contains primarily hydrogen, carbon monoxide and unreacted steam along with lesser amounts of carbon dioxide and unreacted methane.
The hot synthesis gas stream from the reformer tubes is cooled to recover valuable waste heat, which is used to preheat the feed and to generate steam needed for the steam reforming process. In the cooling operation, the reformer effluent is generally passed over one or more beds of water-gas shift catalyst to convert most of the carbon monoxide contained in the synthesis gas to additional hydrogen and carbon dioxide. The synthesis gas is cooled to near ambient temperatures to condense unreacted excess steam so that it can be separated from the raw hydrogen stream prior to sending the stream to a pressure swing adsorption unit (PSA) for product purification.
The PSA produces a purified hydrogen product stream and a PSA desorption effluent or tail gas stream. The tail gas contains unrecovered hydrogen along with other impurities contained in the PSA feed, including carbon monoxide, carbon dioxide, methane and nitrogen. This tail gas stream is typically fired as fuel in the steam reformer furnace to provide the majority of the heat needed to drive the endothermic reforming reaction. Additional heat is provided by also firing a supplemental fuel such as natural gas or refinery fuel gas. The hot flue gas generated in the steam reforming furnace is also cooled to recover waste heat used for preheating steam reformer feed, generating steam and preheating combustion air.
In gasification processes, a suitable hydrocarbon feedstock such as coal, petroleum coke or heavy oil is prepared and fed to one or more gasifiers. In the gasifier vessel, the feedstock is heated and reacted with oxygen to generate a syngas containing predominantly carbon monoxide and hydrogen with lesser amounts of methane, carbon dioxide, nitrogen, argon, steam and sulfur compounds. The gasifier effluent can be quenched via direct injection of water or can be cooled by generating steam in heat recovery equipment.
Since the gasifier effluent contains a significant amount of carbon monoxide, the synthesis gas stream is passed over multiple beds of sulfur-tolerant shift catalyst to convert a portion of the carbon monoxide to hydrogen via the water-gas shift reaction.
Additional waste heat generated by the exothermic shift reaction is recovered in the shift section. The shifted synthesis gas is then routed to an acid gas removal unit (AGR) for removal of sulfur and carbon dioxide contained in the synthesis gas. The raw hydrogen stream from the acid gas removal unit is fed to a PSA for purification of the hydrogen product.
Alternatively, the acid gas removal unit may remove the sulfur compounds, followed by a water-gas shift, followed by either a CO2 removal AGR and a PSA.
There has been much activity recently related to expansion of the Canadian oil sands operations, primarily to upgrade the bitumen or heavy oil contained in the oil sands to a more valuable synthetic crude oil. Since the upgrading process usually consumes large quantities of hydrogen, refiners must choose between the steam reforming process or the gasification process as the means to produce the hydrogen.
In the Fort Hill Sturgeon Upgrader project by Petro-Canada Oil Sands Inc., the refiner is planning on installing steam reformers fed with natural gas to provide a reliable supply of hydrogen for the initial phase(s) of the expansion as discussed in the Application for Approval of Fort Hills Sturgeon Upgrader, Vol. 1, Project Description, Section 2 Processing Facilities, subsection 2.5.2.7 Gasification Unit, Dec. 2006. As the expansion progresses to subsequent phases and heavy oil, asphaltene or petroleum coke becomes available, the refiner plans to install gasifiers to supply essentially all of the hydrogen required for the full expansion. The steam reformer hydrogen plant constructed in Phase 1 will be operated at minimum throughput to reduce the import of natural gas. The Gasification unit will provide the remainder of the total 410,000 Nm3/h hydrogen during Phases 2 and 3. During periods of gasification unit maintenance outages and other operation interruptions, the steam reformer hydrogen plant will be ramped up to meet the hydrogen demand, which will eliminate the need for a spare gasification unit train. The gasification unit allows for potential future CO2 recovery and sequestration.
The problem of operating the catalytic steam reformer even at deep turndown is that it will continue to consume costly feedstock such as natural gas.
It would be desirable to reduce the consumption of catalytic steam reformer feedstock and/or feedstock used as fuel during turndown and/or deep turndown of the catalytic steam reformer.